Methodology of Cost Allocation

May 17, 2013 Robin Kliethermes

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Purpose of Cost Allocation • Determine whether each class of customers is providing the

utility with a reasonable level of revenue necessary to cover the investments and costs of providing service to that class.

• Determine class revenue requirement/responsibility of each class for its equitable share of the utility's total annual cost of providing service within a given jurisdiction. – Creates pricing signals that encourage efficient use of system

capacity. – Avoids undue price discrimination among classes of customers.

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Cost Allocation

- Cost of Service study is an analysis of the total costs a utility incurs to provide service.

* Plant Investment – production, transmission, storage, distribution & general

* Expenses - Operation and Maintenance - Administrative and General - Labor - Taxes

- Class Cost of Service study is an analysis of the total costs incurred by a utility and allocated to various rate classes. 3

Cost Allocation (Cont’d)

- Class Cost of Service Study will: Step 1: Functionalize Costs Step 2: Classify Cost Step 3: Allocate Costs

- At each step ask, “What caused the cost to be incurred?”

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Functionalization

• The grouping of plant investment and operation expense accounts according to the specific function they play in the operations of the utility system.

– Production – Storage (Natural Gas Only) – Transmission – Distribution – Customer – Administrative and General

• Classified as production, transmission, distribution and customer.

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Production-Capacity

38%

Production-Energy

35%

Transmission 4%

Distribution 18%

Customer 5%

Total Functionalized Costs of a Vertically Integrated Electric Utility

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Production 0.72%

Transmission 0.03%

Storage 2.17%

Distribution 76.04%

Customer 21.04%

Total Functionalized Costs of a Natural Gas Utility

Classification

• Classification is a means to divide the functionalized, cost-defining components into:

– Customer Related Costs

• Costs that vary with the number of customers

– Demand Related Costs • Costs that vary with kW of peak demand

– Energy Related Costs • Costs that vary with kWh of energy

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Allocation

• The process of assigning costs to different customer classes.

– Customer classes are based on similarities in usage levels,

voltage levels at which the customer is served and other conditions of service, such as demand meters.

– Customer Categories Include: • Industrial (Transmission, Substation, Primary and Secondary) • Commercial (Primary and Secondary) • Residential (Secondary)

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‘bulk’ transmission lines 230-500 kV

Network switchyard

transmission subs (step-down transformers)

66-110 kV lines

distribution subs (step-down transformers)

distribution lines (pole-top transformers)

Generation (6-14 kV)

step-up transformers

Demand-Energy

Demand

Demand-Customer

Customer Served at Transmission

Customer Served at Primary Voltage

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Foundation For Demand Allocators

- Average Demand – total kWh during a cycle divided by the number of hours in the cycle. - 8760 hours in a year

- Peak Demand – is the maximum hourly demand (load) during the cycle (measured in kW or MW).

- Coincident Peak Load (CP) – a customer class’s peak load at the time of total system peak.

- Non-Coincident Peak Load (NCP) – a customer class’s peak load regardless of when it happens.

- Customer Maximum Demands (MDD) – sum of individual customer demands within a specific class.

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System Load Diversity

-

200

400

600

800

1,000

1,200

1,400

1,600

1,800

2,000

1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24

Res Sm Com Lg Com Sm Ind Lg Ind12

Natural Gas Conversions

• 1 Cubic Meter = 35.31 Cubic Feet • 100 cubic feet (1 ccf) • 2.83 m3

• 1 Therm = 100,000 Btu • 1 ccf • 1 Million British Thermal Units (MMBtu) = 10 Therms

Methods of Allocation Demand-Related Cost Allocation Methods

• Coincident Peak Demand (1CP, 4CP, 12CP)

• Non Coincident Peak Demand (1NCP, 4NCP, 12NCP) – Customer Maximum Demands (MDD)

• Average-Excess Demand – This method uses a weighted average of the average-demand

allocators (weight = system load factor) and the Excess-Demand Allocators (weight = one minus the system load factor).

• Base, Intermediate and Peak (BIP) (Missouri’s Method) – The base portion of this method is a weighted average of the

average demand allocator (weight = system load factor) and the intermediate and peak portions are a weighted average of the average peak demand allocators (weight = one minus the system load factor). 14

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Methods of Allocation (Cont’d) – Energy-Related Cost Allocation Methods

• kWh of Energy Sold or Volumes of Gas Sold – kWh at Meter and at Generator

• Compared to high voltage customers, low voltage customers have higher loss factors because: (1) they are further “downstream” from the generation sources and (2) line losses are inversely related to line voltage levels.

– Customer-Related Cost Allocation Methods • Number of Customer • Weighted Number of Customers – weights can be based on:

– Average meter costs – Average billing costs – Average meter-reading costs

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Customer and Demand-Related Allocation Ex. Distribution Plant Investment in Mains Customer Component

• Typical cost of main per customer multiplied by the number of customers in the class

– Length of main directly associated with a typical customer in each class – The diameter of the main that would be required to serve that customer

Demand Component • Estimated peak day demands of each class

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Methods of Allocation (Cont’d)

Data Requirements To Develop Allocators

Electric Utility Provides: • Hourly load information per customer class based on load

research studies – Diversity Factors

• Line Loss Study • Number of customers served in each customer class at each

voltage level • Monthly usage (kWh) and demand (kW) information for each

customer class – Number of days per bill cycle

• Customer related cost data – Meter and Billing costs

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Data Requirements (Cont’d)

Natural Gas Utility Provides: •Volumes of gas sold and transported by customer class and by bill cycle

– Meter Read Dates or number of days per bill cycle

•Average length and cost of service main for each class of customers

– Usually based on a sample of customers

•Customer related costs – Customer Service costs – Meter costs & House Regulator costs per class of customers

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Sample of Data Output

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RESIDENTIAL

NCP

Demand loss rates 1.0186 1.0237 1.0068 1.0287

RESIDENTIAL

CP

Allocator Usage

• Using the methods of allocation and the data received from the utility, we assign specific allocators to specific functions.

• A general principal to follow is:

– For example, production maintenance expenses are allocated using the same methodology as production plant. Same relationship exists for transmission, storage and distribution expenses.

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Results of Class Cost of Service

• Total cost to serve a class = Expenses + Return on Investment

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Functional Category Residential

Commercial Primary

Commercial Secondary

Industrial Primary

Industrial Secondary

Industrial Substation

Industrial Trans. Total

Production – Demand $128,140,056 $440,413 $38,233,710 $31,571,581 $12,553,553 $10,868,441 $6,685,527 $227,973,813

Production - Energy $40,651,586 $260,498 $19,500,782 $23,129,285 $8,855,237 $8,128,200 $4,680,467 $104,686,585

Transmission $9,532,613 $47,252 $3,577,149 $3,344,128 $1,280,761 $1,174,899 $677,307 $19,114,641

Distribution - Substations $4,706,569 $17,185 $1,190,944 $1,021,363 $396,497 $346,264 $0 $7,159,353

Distribution - Primary $17,272,306 $68,760 $4,765,036 $4,086,533 $1,586,408 $0 $0 $27,259,575

Distribution - Secondary $19,234,824 $0 $4,829,300 $0 $1,229,538 $0 $0 $24,774,193

Customer $30,513,005 $35,199 $2,414,789 $38,870 $10,636 $5,366 $7,155 $32,505,551

Total $250,050,959 $869,307 $74,511,710 $63,191,760 $25,912,630 $20,523,170 $12,050,456 $443,473,710

Seasonal Differentiated Tariffs

• For most electric utilities in Missouri the summer months include June, July, August and September. The remaining eight months are considered winter months.

• For most gas utilities in Missouri the winter months are November, December, January, February and March and the remaining seven months are considered summer months. One gas utility is split evenly with six winter months and six summer months.

• Many Missouri electric utilities peak in the summer, therefore summer rates tend to be higher.

• All gas utilities in Missouri peak in the winter, therefore rates in the winter tend to be higher.

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Using Class Cost of Service To Determine Seasonal Rates Residential

Cost Category Annual Winter Summer

Production - Demand $129,503,853 $65,562,446 $63,941,407

Production - Energy $40,724,337 $23,528,727 $17,195,610

Transmission $9,146,149 $4,880,785 $4,265,364

Distribution - Substations $4,248,888 $2,031,530 $2,217,358

Distribution - Primary $17,000,055 $8,128,274 $8,871,781

Distribution - Secondary $18,991,533 $9,049,533 $9,942,000

Customer $30,436,143 $20,290,762 $10,145,381

Total Costs to be Recovered in Rates $250,050,959 $133,472,059 $116,578,900

# of Customers 189,263

kWh @ Meter 1,904,348,334 1,086,293,179 818,055,155

Monthly Customer Charge $13.40

Energy Costs $0.0214 $0.0217 $0.0210

Demand Costs ($/kWh) $0.0939 $0.0825 $0.1091

Time of Use Tariff

• Time-of-use rates or time-of-day rates, are rates that change based on the time the energy is used. – In a 24-hour day the hours are designated as “On-peak” or

“Off-peak” and sometimes a third option of “Shoulder”. A different rate applies to energy used at the designated times.

• Provides an incentive to move energy usage from peak to off-peak hours.

• Can be used for all classes of customers. – Especially for industrial customers

• Hourly load research data is needed to determine hours of peak and off-peak usage and the level of usage within those hours.

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Sample Industrial Customer Tariff Sheet

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BILLING PERIODS Weekdays Summer Winter Peak 10:00 - 22:00 7:00 - 22:00 Off-Peak 22:00 - 10:00 22:00 - 7:00 Weekends Off-Peak All hours All hours MONTHLY RATE (Secondary, Primary, Substation and Transmission) Summer Winter Customer Charge First 500 kW $1140.56 $1140.56 Over 500 kW $1.81 per kW $1.81 per kW Energy Charge Peak ............................................ $0.0607 per kWh................... $0.0501 per kWh Off-Peak ...................................... $0.0427 per kWh................... $0.0377 per kWh Billed Demand Charge For each kW………………………….$13.12 per kW………………..$5.60 per kW

Sample Large Customer Tariff Sheet (Cont’d)

• Metering Loss Adjustment – Service Metered at Primary Voltage – Where service is provided directly

from a twelve (12) kV circuit feeder and is metered at four (4) kV or twelve (12) kV, the metered kWh and kW will be reduced by one and one-half percent (1.5%).

– Service Metered at Substation Voltage – Where service is metered at four (4) kV or twelve (12) kV directly from a substation the metered kWh and kW will be reduced by two and one-half percent (2.5%).

– Service Metered at Transmission Voltage – Where service is metered at thirty-four (34) kV and above directly from a transmission line, the metered kWh and kW will be reduced by three percent (3%).

• If there is no metering loss adjustment, there would be a separate tariff for each voltage level.

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Sample Residential Tariff Sheet

BILLING PERIODS Weekdays Summer Winter Peak 13:00 - 20:00 7:00 - 22:00 Shoulder 6:00 - 13:00 Shoulder 20:00 - 22:00 Off-Peak 22:00 - 6:00 22:00 - 7:00 Weekends Shoulder 6:00 - 22:00 Off-Peak 22:00 - 6:00 All hours MONTHLY RATE Summer Winter Customer Charge .......................... ........ $18.46 per month .................. $18.46 per month Energy Charge Peak ............................................ $0.2036 per kWh ................... $0.1307 per kWh Shoulder ...................................... $0.1131 per kWh Off-Peak ...................................... $0.0679 per kWh ................... $0.0522 per kWh

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Questions?

Robin Kliethermes Regulatory Economist

Missouri Public Service Commission robin.kliethermes@psc.mo.gov

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